Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-Q

ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended September 30, 2008ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                                to


Commission file number 1-10934

ENBRIDGE ENERGY PARTNERS, L.P.(Exact name of registrant as specified in its charter)

Delaware(State or other jurisdiction of
incorporation or organization)

39-1715850(I.R.S. Employer
Identification No.)


1100 Louisiana
Suite 3300
Houston, TX 77002(Address of principal executive offices and zip code)

(713) 821-2000(Registrant's telephone number, including area code)

Indicate
by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ý

Accelerated Filer o

Non-Accelerated Filer o (Do not check if a smaller
reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o     No ý

The Registrant had 59,838,834 Class A common units outstanding as of October 31, 2008.



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Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS



PART I. FINANCIAL INFORMATIONItem 1.

Financial StatementsConsolidated Statements of Income for the three and nine month periods ended
September 30, 2008 and 2007

3Consolidated Statements of Comprehensive Income for the three and nine month periods
ended September 30, 2008 and 2007

4Consolidated Statements of Cash Flows for the nine month periods ended
September 30, 2008 and 2007

5Consolidated Statements of Financial Position as of September 30, 2008 and
December 31, 2007

6Notes to Consolidated Financial Statements

7Item 2.

Management's Discussion and Analysis of Financial
Condition and Results of Operations

22Item 3.

Quantitative and Qualitative Disclosures About
Market Risk

46Item 4.

Controls and Procedures

48PART II. OTHER INFORMATIONItem 1.

Legal Proceedings

49Item 1A.

Risk Factors

49Item 6.

Exhibits

50Signatures

51Exhibits


In this report, unless the context requires otherwise, references to "we," "us," "our," or the "Partnership" are intended to mean Enbridge
Energy Partners, L.P. and its consolidated subsidiaries. This Quarterly Report on Form 10-Q contains forward-looking statements. These forward-looking statements are
identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "continue," "estimate," "expect," "forecast," "intend," "may,"
"plan," "position," "projection," "strategy," "could," "should," "would," or "will" or the negative of those terms or other variations of them or by comparable terminology. In particular, statements,
expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate revenue, income or cash flow or to make distributions are forward-looking
statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may
differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. For additional
discussion of risks, uncertainties and assumptions, see "Risk Factors" included in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended
December 31, 2007 and in Part II, Item 1A of our quarterly reports on Form 10-Q.

2

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF INCOME

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions, except per unit amounts)Operating revenue

$
2,812.7

$
1,710.9

$
8,180.2

$
5,162.3Operating expensesCost of natural gas (Notes 10 and 11)


2,407.5


1,430.8


7,120.6


4,390.7Operating and administrative


139.9


103.8


378.4


306.6Power


35.0


29.7


104.6


87.1Depreciation and amortization


58.6


45.0


163.1


121.32,641.0


1,609.3


7,766.7


4,905.7Operating income


171.7


101.6


413.5


256.6Interest expense


50.7


23.4


129.7


70.2Other income


0.3


0.4


2.5


2.3Income before income tax expense


121.3


78.6


286.3


188.7Income tax expense


1.9


1.3


5.0


3.7Net income

$
119.4

$
77.3

$
281.3

$
185.0Net income allocable to limited partner units (Note 2)

$
105.3

$
67.9

$
245.5

$
158.6Net income per limited partner unit (basic and diluted) (Note 2)

$
1.09

$
0.75

$
2.58

$
1.87Weighted average limited partner units outstanding


96.9


90.0


95.3


84.8


The accompanying notes are an integral part of these consolidated financial statements.

3

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ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions)Net income

$
119.4

$
77.3

$
281.3

$
185.0Other comprehensive income (loss), net of tax benefit (expense) of $(1.5), $0, $(0.4) and $0.4 (Notes 10 and 11)


257.1


(1.6
)

66.6


(36.6
)Comprehensive income

$
376.5

$
75.7

$
347.9

$
148.4


The
accompanying notes are an integral part of these consolidated financial statements.

4

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ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine months ended
September 30,2008

2007(unaudited; in millions)Cash provided by operating activitiesNet income

$
281.3

$
185.0Adjustments to reconcile net income to net cash provided by operating activities:Depreciation and amortization


163.1


121.3Derivative fair value (gains) losses (Notes 10 and 11)


(17.5
)

17.4Inventory market price adjustments (Note 4)


8.3


4.5Other


20.1


(2.0
)Changes in operating assets and liabilities, net of cash acquired:Receivables, trade and other


(49.2
)

42.3Due from General Partner and affiliates


2.1


2.5Accrued receivables


21.1


116.2Inventory (Note 4)


(98.6
)

(13.6
)Current and long term other assets (Notes 10 and 11)


(9.1
)

(5.4
)Due to General Partner and affiliates (Note 8)


35.4


39.1Accounts payable and other (Notes 3, 10 and 11)


(10.5
)

(5.9
)Accrued purchases


78.1


(116.8
)Interest payable


55.9


28.9Property and other taxes payable


14.8


5.3Settlement of interest rate derivatives (Note 11)


(22.1
)

(0.9
)Net cash provided by operating activities


473.2


417.9Cash used in investing activitiesAdditions to property, plant and equipment


(1,000.2
)

(1,428.4
)Changes in construction payables


(56.0
)

56.4Changes in restricted cash (Note 3)


(10.0
)

Other


(13.0
)

(2.0
)Net cash used in investing activities


(1,079.2
)

(1,374.0
)Cash provided by financing activitiesNet proceeds from unit issuances (Note 7)


221.8


628.8Distributions to partners (Note 7)


(211.8
)

(179.5
)Net borrowings (repayments) under Credit Facility (Note 6)


(13.7
)

120.0Net repayments of commercial paper (Note 6)


(79.4
)

(241.2
)Net proceeds from issuances of long-term debt (Note 6)


790.2


592.8Net cash provided by financing activities


707.1


920.9Net increase (decrease) in cash and cash equivalents


101.1


(35.2
)Cash and cash equivalents at beginning of year


50.5


184.6Cash and cash equivalents at end of period

$
151.6

$
149.4


The
accompanying notes are an integral part of these consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.        CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

September 30,
2008

December 31,
2007(unaudited; dollars in millions)ASSETSCurrent assetsCash and cash equivalents (Note 3)

$
151.6

$
50.5Restricted cash (Note 3)


10.0


Receivables, trade and other, net of allowance for doubtful accounts of $2.0 in 2008 and $1.9 in 2007


208.3


157.8Due from General Partner and affiliates


25.1


27.2Accrued receivables


577.7


598.8Inventory (Note 4)


200.9


110.6Other current assets (Notes 10 and 11)


14.2


14.81,187.8


959.7Property, plant and equipment, net (Note 5)


6,406.6


5,554.9Goodwill


256.5


256.5Intangibles, net


89.7


91.5Other assets, net (Notes 10 and 11)


40.5


29.0$
7,981.1

$
6,891.6LIABILITIES AND PARTNERS' CAPITALCurrent liabilitiesDue to General Partner and affiliates (Note 8)

$
102.3

$
45.8Accounts payable and other (Notes 3, 9, 10 and 11)


271.5


400.4Accrued purchases


681.9


603.8Interest payable


76.8


20.9Property and other taxes payable


37.3


22.5Current maturities of long term debt


442.8


31.01,612.6


1,124.4Long term debt (Note 6)


3,163.5


2,862.9Notes payable to affiliate


130.0


130.0Other long-term liabilities (Notes 9, 10 and 11)


145.6


202.85,051.7


4,320.1Commitments and contingencies (Note 9)Partners' capital (Note 7)Class A common units (59,838,834 at September 30, 2008 and 55,238,834 at December 31, 2007)


1,529.1


1,340.7Class B common units (3,912,750 at September 30, 2008 and December 31, 2007)


77.6


72.9Class C units (19,158,153 at September 30, 2008 and 18,073,367 at December 31, 2007)


921.3


874.1i-units (14,355,600 at September 30, 2008 and 13,564,086 at December 31, 2007)


557.8


515.3General Partner


71.4


62.9Accumulated other comprehensive loss (Notes 10 and 11)


(227.8
)

(294.4
)2,929.4


2,571.5$
7,981.1

$
6,891.6


The accompanying notes are an integral part of these consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.        NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1.     BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United
States of America for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X.
Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements.
In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of
September 30, 2008 and December 31, 2007; the results of operations for the three and nine month periods ended September 30, 2008 and 2007; and our cash flows for the nine month
periods ended September 30, 2008 and 2007. We derived the Consolidated Statement of Financial Position as of December 31, 2007, from the audited financial statements included in our 2007
Annual Report on Form 10-K. The results of operations for the three and nine month periods ended September 30, 2008, should not be taken as indicative of the results to be
expected for the full year due to seasonality of portions of the natural gas business, timing and completion of our construction projects, maintenance activities and the impact of forward natural gas
prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Our interim consolidated financial statements
should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31,
2007.

Comparative Amounts

We have made reclassifications to the amounts reported in our prior year consolidated statement of financial position and our
consolidated statements of cash flows to conform to our current year presentation. We reclassified $2.8 million of "Environmental liabilities" to "Other long-term liabilities" in
our December 31, 2007 consolidated statement of financial position. We also reclassified $1.8 million for changes in "Environmental liabilities" to "Other" under
the operating section of our consolidated statements of cash flows. In addition, we reclassified $3.5 million for changes in the balance of "Current income tax payable" to "Property and other
taxes payable" on our consolidated statements of cash flows.

2.     NET INCOME PER LIMITED PARTNER UNIT

Net income per limited partner unit is computed by dividing net income, after we deduct our allocations to our general partner, Enbridge Energy
Company, Inc. (the "General Partner"), by the weighted average number of our limited partner units outstanding. The General Partner's allocation is equal to an amount based upon its general
partner interest, adjusted to reflect an amount equal to its incentive distributions and an amount required to reflect depreciation on the General Partner's historical

7

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

cost
basis for assets contributed on formation of the Partnership. We have no dilutive securities. Net income per limited partner unit was determined as follows:

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions, except per unit amounts)Net income

$
119.4

$
77.3

$
281.3

$
185.0Allocations to the General Partner:Net income allocated to the General Partner


(2.4
)

(1.5
)

(5.6
)

(3.7
)Incentive distributions allocated to the General Partner


(11.7
)

(7.9
)

(30.1
)

(22.6
)Historical cost depreciation adjustments








(0.1
)

(0.1
)(14.1
)

(9.4
)

(35.8
)

(26.4
)Net income allocable to limited partner units

$
105.3

$
67.9

$
245.5

$
158.6Net income per limited partner unit (basic and diluted)

$
1.09

$
0.75

$
2.58

$
1.87Weighted average limited partner units outstanding


96.9


90.0


95.3


84.8


3.     CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has
presented for payment. Accordingly, obligations for which we have issued check payments that have not yet been presented to the financial institution in the amounts of approximately
$33.4 million at September 30, 2008 and $38.5 million at December 31, 2007, are included in "Accounts payable and other" on our consolidated statements of financial
position.

In
September 2008, following the bankruptcy filing by Lehman Brothers Bank, FSB, as discussed in Note 6, Bank of America, N.A., as administrative agent to our Credit Facility,
required us to post a certificate of deposit issued by Bank of America, N.A. for $10.0 million as collateral against the letters of credit outstanding on our Credit Facility, which we have
presented as "Restricted cash" on our consolidated statements of financial position.

4.     INVENTORY

Inventory is comprised of the following:

September 30,
2008

December 31,
2007(in millions)Materials and supplies

$
3.9

$
3.9Liquids inventory


27.7


6.7Natural gas and natural gas liquids inventory


169.3


100.0$
200.9

$
110.6


The
cost of natural gas on our consolidated statements of income includes charges totaling $8.3 million for the three and nine months ended September 30, 2008 and
$4.5 million for the three and nine months ended September 30, 2007 that we recorded to reduce the cost basis of our natural gas inventory to reflect market value.

8

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

5.     PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

September 30,
2008

December 31,
2007(in millions)Land

$
17.6

$
14.3Rights-of-way


417.5


345.8Pipelines


4,167.7


2,703.2Pumping equipment, buildings and tanks


984.9


854.7Compressors, meters, and other operating equipment


616.2


536.1Vehicles, office furniture and equipment


151.9


123.3Processing and treating plants


297.9


200.4Construction in progress


943.6


1,813.9Total property, plant and equipment


7,597.3


6,591.7Accumulated depreciation


(1,190.7
)

(1,036.8
)Property, plant and equipment, net

$
6,406.6

$
5,554.9


6.     DEBT

Credit Facility

In March 2008, we requested and received approval from the parties named as lenders to our Credit Facility for a one year extension of
the maturity date from April 4, 2012 to April 4, 2013.

At
September 30, 2008, we had $386.2 million outstanding under our Credit Facility at a weighted average interest rate of 3.82% and letters of credit totaling
$101.2 million. The amounts we may borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit
outstanding. The terms of our Credit Facility include commitments from 14 different lenders to borrow up to $1,250 million, at September 30, 2008. One of the committed lenders to our
Credit Facility, Lehman Brothers Bank, FSB ("Lehman BB"), a subsidiary of Lehman Brothers Holdings, Inc. filed for bankruptcy protection under Chapter 11 of the United States ("U.S.")
Bankruptcy Code in September 2008. Lehman BB has commitments of $82.5 million that we currently cannot access; effectively reducing the amounts available to us under our Credit Facility to
$1,167.5 million. We are working with other financial institutions to assume Lehman BB's commitment. The remaining lenders under our Credit Facility continue to honor our funding requests.

Excluding
the commitments from Lehman BB, at September 30, 2008, we could borrow $490.1 million under the terms of our Credit Facility, determined as follows:

September 30,
2008(in millions)Total credit available under Credit Facility

$
1,250.0Less:

Amounts outstanding under Credit Facility


(386.2
)Balance of letters of credit outstanding


(101.2
)Principal amount of commercial paper issuances


(190.0
)Lehman Brothers Bank, FSB commitment


(82.5
)Total amount we could borrow at September 30, 2008

$
490.1


Individual
borrowings under the terms of our Credit Facility generally become due and payable at the end of each contract period, which typically is a period of three months or less. We
have the option to

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

repay
these amounts on a non-cash basis by net settling with the parties to our Credit Facility by contemporaneously borrowing at the then current rate of interest and repaying the amounts
due. During the nine months ended September 30, 2008, we net settled borrowings of approximately $490 million on a non-cash basis.

Commercial Paper Program

We have a commercial paper program that provides for the issuance of up to $600 million of commercial paper that is supported by
our Credit Facility. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions, at rates that are generally
lower than the rates available under our Credit Facility. At September 30, 2008 and December 31, 2007, respectively, we had $189.5 million and $268.5 million of commercial
paper outstanding, net of unamortized discount of $0.5 million and $1.5 million, at weighted average interest rates of 3.19% and 5.36%. At September 30, 2008 we could issue an
additional $410 million in principal amount under our commercial paper program. The commercial paper we can issue is limited by the credit available under our Credit Facility.

We
have the ability and intent to refinance all of our commercial paper obligations on a long-term basis under our unsecured long-term Credit Facility.
Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated statements of financial position.

Senior Notes

In April 2008, we issued and sold in a private offering $400 million in principal amount of our 6.5% Notes due April 15,
2018 and $400 million in principal amount of our 7.5% Notes due April 15, 2038, which we collectively refer to as the Notes. We received net proceeds from the offering of approximately
$790.2 million after initial purchasers' discounts and payment of offering expenses. We used a portion of the proceeds we received from this offering to repay outstanding issuances of
commercial paper and borrowings under our Credit Facility that we had previously used to finance a portion of our capital expansion projects. We temporarily invested the remaining proceeds which we
later used to fund additional expenditures under our capital expansion programs. The Notes do not contain any covenants restricting our issuance of additional indebtedness and rank equally with all of
our other existing and future unsecured and unsubordinated indebtedness. Interest on the Notes is payable April 15th and October 15th of each year and we may redeem the
Notes for cash in whole or in part at any time, at our option.

In
August 2008, we completed the offers to exchange all of the Notes, which had not been registered under the Securities Act of 1933, as amended (the "Securities Act"), for notes with
identical terms that had been registered under the Securities Act.

We
received tenders for $395 million in aggregate principal amount of our outstanding $400 million of 6.50% Series A Notes due 2018, which we exchanged for
$395 million of our 6.50% Series B Notes due
2018. We also received tenders for all $400 million in aggregate principal amount of our 7.50% Series A Notes due 2038, which we exchanged for $400 million of our 7.50%
Series B Notes due 2038.

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

7.     PARTNERS' CAPITAL

The following table sets forth the distributions, as approved by the Board of Directors of Enbridge Energy Management, L.L.C. ("Enbridge Management") during the
nine months ended September 30, 2008:

Distribution
Declaration
Date

Distribution
Payment Date

Record Date

Distribution
per Unit

Cash
available for
distribution

Amount of
Distribution
of i-units to
i-unit
Holders(1)

Amount of
Distribution
of Class C
units to
Class C unit
Holders(2)

Retained
from
General
Partner(3)

Distribution
of CashJuly 28, 2008

August 14, 2008

August 6, 2008

$
0.990

$
108.0

$
13.9

$
18.6

$
0.7

$
74.8April 28, 2008

May 15, 2008

May 7, 2008

$
0.950

$
102.2

$
13.1

$
17.5

$
0.6

$
71.0January 28, 2008

February 14, 2008

February 6, 2008

$
0.950

$
96.7

$
12.9

$
17.2

$
0.6

$
66.0


---

Issuance of Class A Common Units

On March 3, 2008, we issued and sold 4.6 million Class A common units, including 0.6 million units from the
over-allotment option that was exercised by the underwriters, at a price to the public of $49.00 per unit, for proceeds of approximately $217.2 million, net of underwriters'
discounts, commissions and issuance costs. In addition, our general partner contributed approximately $4.6 million to us to maintain its two percent general partner interest. We used the
proceeds from this offering to partially reduce outstanding commercial paper we issued and amounts we previously borrowed under our Credit Facility to finance a portion of our capital expansion
projects. We invested a portion of the proceeds for use in future periods to fund additional expenditures under our capital expansion projects.

8.     RELATED PARTY TRANSACTIONS

We, our general partner and Enbridge Pipelines Inc. ("Enbridge Pipelines"), a subsidiary of Enbridge Inc., regularly collaborate on construction
projects that are mutually beneficial to our respective customers and operations. Examples of such projects include the Southern Access and Alberta Clipper projects where we are constructing the
United States portion of the projects and Enbridge Pipelines is constructing the Canadian portion. In September 2008, we acquired for $21.1 million, approximately 22 miles of
36 inch diameter line pipe from our general partner for our use in constructing the Alberta Clipper project. The line pipe was initially obtained by our general partner for use in constructing
the Southern Access extension, which has been delayed due to a protracted regulatory process.

9.     COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent
to liquid hydrocarbon and natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate
environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover environmental liabilities associated with the
Lakehead system assets through insurance, the General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets
prior to the transfer to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the
purpose of assessing whether

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

any
remediation is required in light of current regulations, and to date, no material environmental risks have been identified.

In
October of 2008, we received a letter from the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration ("PHMSA") alleging violations of federal
pipeline safety regulations and proposing a $2.4 million fine related to an unexpected release and fire on line 3 of our Lakehead System that occurred during planned maintenance near our
Clearbrook, Minnesota, terminal in November 2007. A provision for the amount of the fine has been made in "Short term environmental liabilities."

As
of September 30, 2008 and December 31, 2007, we have recorded $5.7 million and $3.4 million, respectively, in "Accounts payable and other" and
$3.0 million and $2.8 million, respectively, in "Other long-term liabilities," primarily to address remediation of contaminated sites, asbestos containing materials,
management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets, and penalties we have been or expect to be assessed.

Legal Proceedings

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in
whole or in part, by insurance. We believe that the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition.

10.   FAIR VALUE MEASUREMENTS

We adopted the provisions of Statement of Financial Accounting Standards No. 157,Fair Value Measurement,
or SFAS No. 157, as of January 1, 2008. SFAS No. 157 provides guidance for determining fair value and requires increased disclosure regarding the inputs to valuation techniques
used to measure fair value. SFAS No. 157 defines fair value as an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly
transaction with market participants at the measurement date. We apply the provisions of SFAS No. 157 to fair values we report for our derivative instruments and annual disclosures associated
with the fair values of our outstanding indebtedness.

We
utilize a mid-market pricing convention for valuation as a practical expedient for assigning fair value to our derivative assets and liabilities. In the case of our
liabilities, our nonperformance risk is considered in the valuation, based upon the ratings assigned to our debt obligations by the nationally recognized statistical ratings organizations. We present
the fair value of our derivative contracts net of cash paid or received pursuant to collateral agreements on a net-by-counterparty basis in our consolidated statements of
financial position when we believe a legal right of setoff exists under an enforceable netting agreement. Our credit exposure for over-the-counter derivatives is directly with
our counterparty and continues until the maturity or termination of the contracts. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

We
consider credit and nonperformance risk in our valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in
our assessment of credit and nonperformance risk. We estimate a credit reserve for our outstanding derivative assets and liabilities at an individual transaction level in conjunction with the
provisions of our master netting arrangements. Our assessment of credit and nonperformance risk did not affect our determination of the fair value of these derivative assets and liabilities. Likewise,
no reserves were made in determining the fair value of our outstanding liabilities as a result of our own credit standing.

SFAS
No. 157 establishes a hierarchy which prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in
active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for
categorizing assets and liabilities that are measured at fair

12

---



Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

value
pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:



Derivative
contracts can be exchange-traded or over-the counter ("OTC") traded. We generally value exchange-traded derivatives within portfolios calibrated to market clearing
levels on a daily basis. We value OTC derivatives using broker information based on executed market transactions that we have corroborated with other observable market data. For OTC derivatives that
trade in liquid markets, such as generic forwards, swaps, and options, inputs can generally be verified and valuation does not involve significant management judgment.

Certain
OTC derivatives trade in less liquid markets with limited pricing information, and the determination of fair value for these derivatives is inherently more difficult. Such
instruments are classified within Level 3 of the fair value hierarchy. We include the fair value of financial assets and liabilities in Level 3 as a default due to limited market data or
in most cases, due to lacking binding
broker quotes to corroborate pricing data as required by current interpretations of SFAS No. 157 Level 2 requirements. Financial assets and liabilities that are categorized in
Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of Level 2 criteria is modified
in practice to include non-binding market corroborated data.

The
following table sets forth by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of
September 30, 2008. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the
significance of a particular input to the fair value measurement

13

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (Continued)

requires
judgment, and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy.

Fair Value at September 30, 2008Recurring fair value measures

Level 1

Level 2

Level 3

Total(in millions)Assets:Derivative instruments, net

$


$


$
12.7

$
12.7Liabilities:Derivative instruments, net


(157.6
)




(95.5
)

(253.1
)Total

$
(157.6
)
$


$
(82.8
)
$
(240.4
)


The
table below provides a summary of changes in the fair value of our Level 3 financial assets and liabilities for the nine months ended September 30, 2008. As reflected
in the table, the net unrealized gain on Level 3 financial assets and liabilities was $4.6 million for the nine months ended September 30, 2008, which resulted from forward price
decreases in natural gas, natural gas liquids, or NGLs, and crude oil derivative instruments that we held at September 30, 2008.

Derivative
Instruments, net(in millions)Balance at January 1, 2008

$
(160.6
)Realized and unrealized net gains


79.3Purchases and settlements


(1.5
)Transfer in (out) of Level 3


Balance at September 30, 2008

$
(82.8
)Change in unrealized net gains relating to instruments still held at September 30, 2008

$
4.6


11. DERIVATIVE FINANCIAL INSTRUMENTS

Our net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGLs, condensate and
fractionation margins (the relative price differential between NGL sales and the offsetting natural gas purchases). Our exposure to commodity price risk exists within our Natural Gas and Marketing
segments. We use derivative instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to manage the risks associated with market fluctuations
in commodity prices, as well as to reduce the volatility of our cash flows. Our formal hedging program provides a control structure and governance for our hedging activities specific to identified
risks and time periods, which are subject to the approval and monitoring by a committee of senior management. Based on our risk management policies, all of our derivative instruments are employed in
connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion
of our exposure to the variability in future cash flows associated with forecasted natural gas and NGL sales and purchases through 2013 in accordance with our risk management policies.

Accounting Treatment

We record all derivative instruments in our consolidated financial statements at fair value pursuant to the provisions of Statement of
Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities, or SFAS No. 133, and the guidance
set forth in SFAS No. 157 as discussed in Note 10 above. We adjust our consolidated financial statements each period for changes in the fair value of our derivative instruments, which we
refer to as "marking to market" or "mark-to-market." For those derivative instruments that do not qualify for hedge accounting, we record all changes in fair market value
through our consolidated statements of income each period.

14

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Table of Contents

Under the guidance of SFAS No. 133, if a derivative instrument does not qualify as a hedge, or is not designated as a hedge, the derivative instrument is
adjusted to its fair value each period with the increases and decreases in fair value recorded in our consolidated statements of income as increases and decreases in "Cost of natural gas" for our
commodity-based derivatives. Our cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or
receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the
derivative instrument occurs.

If
a derivative instrument qualifies and is designated as a cash flow hedge, a hedge of a forecasted transaction or future cash flows, any unrealized
mark-to-market gain or loss is deferred in "Accumulated other comprehensive income" ("AOCI"), a component of "Partners' capital," until the underlying hedged transaction
occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement. At inception and on a quarterly basis, we formally
assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair value is recognized each period
in earnings. Realized gains and losses on derivative instruments that are designated as hedges and qualify for hedge accounting are included in "Cost of natural gas" in
the period the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges, for which hedge accounting has been discontinued, remain in AOCI until the underlying physical
transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period, or within an additional two-month period of time
thereafter. Generally, our preference is for our derivative instruments to receive hedge accounting treatment whenever possible, to mitigate the non-cash earnings volatility that arises
from recording the changes in fair value of our derivative instruments through earnings. To qualify for cash flow hedge accounting as set forth in SFAS No. 133, very specific requirements must
be met in terms of hedge structure, hedge objective and hedge documentation. Additionally, both the counterparty credit standing and the ability to perform must be considered for both the hedge
transaction and the physical transaction being hedged.

Non-Qualified Hedges

Many of our derivative instruments qualify for hedge accounting treatment under the specific requirements of SFAS No. 133.
However, we have four primary transaction types associated with our commodity derivative instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result,
these derivative instruments do not qualify for hedge accounting under SFAS No. 133 and are referred to as "non-qualified." Non-qualified derivative instruments are
marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in "Cost of natural gas" in our consolidated statements of
income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to
changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and when the associated derivative instrument contract settlement is made.

The
four primary transaction types that do not qualify for hedge accounting are as follows:



15

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Table of Contents



In
each of the instances described above, the underlying physical purchase, storage and sale of natural gas and NGLs are accounted for on a historical cost or market basis rather than on
the mark-to-market basis we utilize for the derivative instruments employed to mitigate the commodity price risk associated with our storage and transportation assets. This
difference in accounting treatment between the derivative instrument and the underlying transaction (i.e., the derivative instruments are recorded at fair value while the physical transactions
are recorded at historical cost) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were
consummated.

The
following table presents the unrealized gains and losses associated with changes in the fair value of our derivative instruments, which are recorded as an element of "Cost of natural
gas" for our

16

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Table of Contents

commodity-based
derivative instruments in our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

Three months ended
September 30,

Nine months ended
September 30,Derivative fair value gains (losses)

2008

2007

2008

2007(in millions)Natural Gas segmentHedge ineffectiveness

$
0.1

$
(0.5
)
$
(1.1
)
$
(0.2
)Non-qualified hedges


36.5


(7.2
)

42.5


(13.2
)Marketing segmentNon-qualified hedges


11.0


2.9


(23.9
)

(4.0
)Derivative fair value gains (losses)

$
47.6

$
(4.8
)
$
17.5

$
(17.4
)


De-designation and Settlement of Derivatives

We record the change in fair value of our cash flow hedges in AOCI until the derivative instruments are settled, at which time they are
reclassified from AOCI to earnings. Also included in AOCI at September 30, 2008 are unrecognized losses of approximately $1.6 million associated with cash flow hedges that were
subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. For the three and nine
months ended September 30, 2008, we reclassified losses of $52.1 million and $112.4 million, respectively, from AOCI to "Cost of natural gas" on our consolidated statements of
income for the fair value of derivative instruments that were settled.

In
connection with our April 2008 issuance and sale of $800 million in principal amount of Notes, we paid $22.1 million to settle treasury locks we entered to hedge the
interest payments on a portion of these obligations through the maturity date of the Notes maturing in 2038. The $22.1 million is being amortized from AOCI to "Interest expense" over the
30-year term of the Notes.

Derivative Positions

Our derivative financial instruments are included at their fair values in our consolidated statements of financial position as follows:

September 30,
2008

December 31,
2007(in millions)Other current assets

$
2.6

$
6.5Other assets, net


9.6


6.4Accounts payable and other


(118.3
)

(165.5
)Other long-term liabilities


(134.3
)

(192.9
)$
(240.4
)
$
(345.5
)


The
decrease in our obligation associated with derivative activities is primarily due to a decline in forward and daily natural gas, NGL and condensate prices from December 31,
2007 to September 30, 2008. Our portfolio of derivative financial instruments is largely comprised of long-term fixed price natural gas and NGL sales and purchase agreements.

We
present the fair value of our derivative contracts on a net-by-counterparty basis in our consolidated statements of financial position when we believe a legal
right of setoff exists under an enforceable netting agreement. Our credit exposure for OTC derivatives is directly with our counterparty

17

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Table of Contents

and
continues until the maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

The
table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).

September 30,
2008

December 31,
2007(in millions)Counterparty Credit Quality*AAA

$


$
AA


(164.0
)

(298.3
)A


(76.4
)

(47.2
)Lower than A





Total

$
(240.4
)
$
(345.5
)


---



12. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is
available and evaluated regularly by our Chief Operating Decision Maker in deciding how resources are allocated and performance is assessed.

Each
of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating
strategies. We have segregated our business activities into three distinct operating segments:



The
following tables present financial information about our business segments:

For the three months ended September 30, 2008Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
209.3

$
2,233.4

$
1,352.8

$


$
3,795.5Less: Intersegment revenue


0.1


928.5


54.2





982.8Operating revenue


209.2


1,304.9


1,298.6





2,812.7Cost of natural gas





1,122.4


1,285.1





2,407.5Operating and administrative


52.0


83.8


2.5


1.6


139.9Power


35.0











35.0Depreciation and amortization


26.7


31.5


0.4





58.6Operating income


95.5


67.2


10.6


(1.6
)

171.7Interest expense











50.7


50.7Other income











0.3


0.3Income before income tax expense


95.5


67.2


10.6


(52.0
)

121.3Income tax expense











1.9


1.9Net income

$
95.5

$
67.2

$
10.6

$
(53.9
)
$
119.4Capital expenditures (excluding acquisitions)

$
261.1

$
62.7

$


$
4.3

$
328.1


---

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Table of Contents

For the three months ended September 30, 2007Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
138.1

$
1,376.0

$
790.3

$


$
2,304.4Less: Intersegment revenue





528.7


64.8





593.5Operating revenue


138.1


847.3


725.5





1,710.9Cost of natural gas





711.2


719.6





1,430.8Operating and administrative


33.9


68.1


2.3


(0.5
)

103.8Power


29.7











29.7Depreciation and amortization


16.9


27.7


0.4





45.0Operating income


57.6


40.3


3.2


0.5


101.6Interest expense











23.4


23.4Other income











0.4


0.4Income before income tax expense


57.6


40.3


3.2


(22.5
)

78.6Income tax expense











1.3


1.3Net income

$
57.6

$
40.3

$
3.2

$
(23.8
)
$
77.3Capital expenditures (excluding acquisitions)

$
354.4

$
186.8

$
0.1

$
(4.4
)
$
536.9


---

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Table of Contents

As of and for the nine months ended September 30, 2008Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
555.5

$
6,388.2

$
4,025.8

$


$
10,969.5Less: Intersegment revenue


0.3


2,582.9


206.1





2,789.3Operating revenue


555.2


3,805.3


3,819.7





8,180.2Cost of natural gas





3,302.8


3,817.8





7,120.6Operating and administrative


130.8


235.8


7.1


4.7


378.4Power


104.6











104.6Depreciation and amortization


73.0


88.8


1.3





163.1Operating income


246.8


177.9


(6.5
)

(4.7
)

413.5Interest expense











129.7


129.7Other income











2.5


2.5Income before income tax expense


246.8


177.9


(6.5
)

(131.9
)

286.3Income tax expense











5.0


5.0Net income

$
246.8

$
177.9

$
(6.5
)
$
(136.9
)
$
281.3Total assets

$
3,709.9

$
3,692.5

$
353.1

$
225.6

$
7,981.1Capital expenditures (excluding acquisitions)

$
762.8

$
226.6

$


$
10.8

$
1,000.2


---

As of and for the nine months ended September 30, 2007Liquids

Natural Gas

Marketing

Corporate(1)

Total(in millions)Total revenue

$
400.3

$
4,084.7

$
2,634.0

$


$
7,119.0Less: Intersegment revenue





1,767.6


189.1





1,956.7Operating revenue


400.3


2,317.1


2,444.9





5,162.3Cost of natural gas





1,966.2


2,424.5





4,390.7Operating and administrative


108.2


190.3


5.8


2.3


306.6Power


87.1











87.1Depreciation and amortization


50.0


70.1


1.2





121.3Operating income


155.0


90.5


13.4


(2.3
)

256.6Interest expense











70.2


70.2Other income











2.3


2.3Income before income tax expense


155.0


90.5


13.4


(70.2
)

188.7Income tax expense











3.7


3.7Net income

$
155.0

$
90.5

$
13.4

$
(73.9
)
$
185.0Total assets

$
2,624.1

$
3,261.0

$
261.6

$
207.1

$
6,353.8Capital expenditures (excluding acquisitions)

$
847.8

$
572.7

$
1.6

$
6.3

$
1,428.4


---

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Table of Contents

13. SUBSEQUENT EVENT

Distribution to Partners

On October 13, 2008, the Board of Directors of Enbridge Management declared a distribution payable to our partners on
November 14, 2008. The distribution will be paid to
unitholders of record as of November 6, 2008, of our available cash of $108.8 million at September 30, 2008, or $0.990 per common unit. Of this distribution, $74.9 million
will be paid in cash, $14.3 million will be distributed in i-units to our i-unitholder, $18.9 million will be distributed in Class C units to the holders
of our Class C units and $0.7 million will be retained from the General Partner in respect of the i-unit and Class C unit distributions.

14. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standard Board, or FASB, issued Statement No. 161,Disclosures
about Derivative Instruments and Hedging Activities, which is effective for fiscal years and interim periods beginning after November 15, 2008. The statement requires
qualitative disclosures about a company's strategies and objectives for using derivatives, quantitative disclosures about fair value gains and losses on derivatives, and disclosures of
credit-risk-related contingent features in derivative instruments. We do not anticipate adopting the provisions of this pronouncement early. We do not expect our adoption of
this pronouncement to have a material affect on our financial statements other than modifications to our existing derivative disclosures to conform to the requirements set forth in the statement.

Calculation of Earnings Per Unit

In March 2008, the Emerging Issues Task Force, or EITF reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships. The pronouncement prescribes the
manner in which a master limited partnership, or MLP, should allocate and present earnings per unit using the two-class method set forth in FASB Statement No. 128, Earning per Share. Under the
two-class method, current period earnings are allocated to the general partner (including any embedded
incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the partnership agreement. To the extent the partnership agreement does not
explicitly limit distributions to the general partner; any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for
available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner
and limited partners based on their respective sharing of losses specified in the partnership agreement for the period. EITF 07-4 is to be applied retrospectively for all financial
statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is
not permitted. We expect to adopt EITF 07-4 for our quarter ending March 31, 2009. We are currently evaluating the effect this pronouncement will have on our present
computation of earnings per unit.

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Table of Contents

Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read together with our
consolidated financial statements and the accompanying notes included in "Item 1. Financial Statements" of this report.

Additionally,
this quarterly report on Form 10-Q should be read in conjunction with our Annual Report on Form 10-K for the year ended
December 31, 2007.

DISRUPTION TO FUNCTIONING OF CAPITAL MARKETS

Multiple events during 2008 involving numerous financial institutions have effectively restricted current liquidity within the capital
markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to
the financial sector, capital markets currently remain constrained. We expect that our ability to raise debt and equity at prices that are similar to offerings in recent years to be limited over the
next three to six months and possibly longer should capital markets remain constrained.

In
the weeks following the third quarter, our unit price declined to a closing low of $27.07 on October 10, 2008. Since that date our unit price recovered partially to a level of
$37.89 on October 30, 2008. We intend to move forward with our planned internal growth projects, although our capital spending, particularly on the natural gas side of our business, will be
reduced to moderate our capital raising requirements. In the near-term we will focus on maintaining sufficient liquidity to fund our growth programs, see "Liquidity and Capital Resources."
Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms than our most recent offerings and could involve the sale of non-core assets.

RESULTS OF OPERATIONSOVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following
activities:



We
conduct our business through three business segments: Liquids, Natural Gas and Marketing. These segments are strategic business units established by senior management to facilitate
the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

22

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Table of Contents

The
following table reflects our operating income by business segment and corporate charges for the three and nine month periods ended September 30, 2008 and 2007:

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions)Operating IncomeLiquids

$
95.5

$
57.6

$
246.8

$
155.0Natural Gas


67.2


40.3


177.9


90.5Marketing


10.6


3.2


(6.5
)

13.4Corporate, operating and administrative


(1.6
)

0.5


(4.7
)

(2.3
)Total Operating Income


171.7


101.6


413.5


256.6Interest expense


50.7


23.4


129.7


70.2Other income


0.3


0.4


2.5


2.3Income tax expense


1.9


1.3


5.0


3.7Net Income

$
119.4

$
77.3

$
281.3

$
185.0


Several
types of arrangements in our Natural Gas and Marketing segments expose us to market risk associated with changes in commodity prices where we receive natural gas or NGLs in
return for the services we provide, or where we purchase natural gas or NGLs. We employ derivative financial instruments to reduce our exposure to natural gas and NGL price volatility. Some of these
derivative financial instruments do not qualify for hedge accounting under the provisions of Statement of Financial Accounting Standards No. 133,Accounting for
Derivative Instruments and Hedging Activities(SFAS No. 133), which can create volatility in our earnings that can be significant. However, these fluctuations in
earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument. Based on our risk management policies, all of our derivative instruments are employed in
connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

Summary Analysis of Operating Results

Liquids

Operating income from our Liquids segment increased by $37.9 million to $95.5 million for the three months ended
September 30, 2008, from the $57.6 million for the same period of 2007. Operating income for the nine months ended September 30, 2008 increased by $91.8 million to
$246.8 million from $155.0 million for the same period of 2007. The increase in operating income of our Liquids segment is primarily due to the following:



Natural Gas

Operating income from our Natural Gas segment increased by $26.9 million to $67.2 million for the three months ended
September 30, 2008 from the $40.3 million for the same period of 2007. Operating income for the nine months ended September 30, 2008 increased by $87.4 million to
$177.9 million, from

23

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Table of Contents

$90.5 million
for the comparable period in 2007. The following factors affected the operating income of our Natural Gas business:



For
the nine months ended September 30, 2008, in addition to the factors discussed above, we had $41.4 million of unrealized, non-cash
mark-to-market gains, representing a $54.8 million improvement from the $13.4 million of losses we experienced in the same period of 2007. Additionally, operating
income for the nine months ended September 30, 2008 was not affected by unscheduled maintenance at our Zybach processing facility and measurement losses which negatively affected operating
income during the same period of 2007.

Marketing

Operating income from our Marketing segment increased by $7.4 million to $10.6 million for the three months ended
September 30, 2008 compared to $3.2 million in the same period in 2007. For the nine months ended September 30, 2008, operating income decreased by $19.9 million to an
operating loss of $6.5 million from operating income of $13.4 million in the same period of 2007. The operating results of our Marketing segment for the three months ended
September 30, 2008 were positively affected by $11.0 million of unrealized, non-cash, mark-to-market gains associated with derivative financial
instruments that do not qualify for hedge accounting treatment under SFAS No. 133 as compared with $2.9 million for the same period in 2007. Offsetting the unrealized
non-cash, mark-to-market gains were $6.1 million and $3.0 million of non-cash charges for the three months ended September 30, 2008
and 2007, respectively, we recorded to reduce the cost basis of our natural gas inventory to fair market value. Both the non-cash, mark-to-market gains and
revaluation charges resulted from declines in the price of natural gas during the three months ended September 30, 2008.

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Table of Contents

Derivative Transactions and Hedging Activities

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of SFAS
No. 133, and the guidance set forth in Statement of Financial Accounting Standards No. 157,Fair Value Measurement("SFAS
No. 157"). For those derivative instruments that do not qualify for hedge accounting, we record all changes in fair market value through our consolidated statements of income each period. Based
on our risk management policies, all of our derivative instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the
objective of speculating on interest rates or commodity prices.

The
fair values of all our derivative instruments reflect our best estimate of the price we would receive for selling an asset or pay to transfer a liability in an orderly transaction
with market participants at the measurement date. SFAS No. 157 defines how we are to determine fair value, establishes criteria for measuring fair value, and requires additional disclosures for
assets and liabilities that we report at fair value. We adopted the provisions of SFAS No. 157 prospectively beginning January 1, 2008, which did not affect our results of operations,
financial condition or cash flows due to the nature of our derivative instruments and our existing valuation methods.

Our
unrealized, non-cash mark-to-market gains of $47.6 million and $17.5 million for the three and nine months ended
September 30, 2008, are primarily the result of lower forward and daily prices of natural gas and NGLs relative to June 30, 2008 and December 31, 2007, respectively. The changes
in fair value of our portfolio of commodity-based derivative instruments that do not qualify for hedge accounting are a result of the continuing volatility in the underlying prices for natural gas,
NGLs and crude oil. During the three and nine months ended September 30, 2007, rising natural gas and NGL prices relative to the prices at June 30, 2007 and December 31, 2006,
produced unrealized mark-to-market losses for the respective periods. Mark-to-market gains or losses create volatility in our operating results although
the derivative instruments we have in place do not affect our cash flow until they are settled. We expect these non-cash gains and losses to reverse in future periods as we settle the
derivative instruments against the underlying physical transactions. We intend to continue using derivative instruments to hedge our portfolio of natural gas and NGLs because of the economic benefit
we derive from minimizing the volatility in our cash flows. Our continued use of derivative instruments is likely to result in additional unrealized, non-cash gains and losses in the
future.

The
following table presents the unrealized gains and losses associated with changes in the fair value of our derivative instruments, which are recorded as an element of "Cost of natural
gas" in our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

Three months ended
September 30,

Nine months ended
September 30,Derivative fair value gains (losses)

2008

2007

2008

2007(in millions)Natural Gas segmentHedge ineffectiveness

$
0.1

$
(0.5
)
$
(1.1
)
$
(0.2
)Non-qualified hedges


36.5


(7.2
)

42.5


(13.2
)Marketing segmentNon-qualified hedges


11.0


2.9


(23.9
)

(4.0
)Derivative fair value gains (losses)

$
47.6

$
(4.8
)
$
17.5

$
(17.4
)


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Table of Contents

RESULTS OF OPERATIONSBY SEGMENT

Liquids

The following tables set forth the operating results and statistics of our Liquids segment assets for the periods presented:

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions)Operating ResultsOperating revenues

$
209.2

$
138.1

$
555.2

$
400.3Operating and administrative


52.0


33.9


130.8


108.2Power


35.0


29.7


104.6


87.1Depreciation and amortization


26.7


16.9


73.0


50.0Operating expenses


113.7


80.5


308.4


245.3Operating Income

$
95.5

$
57.6

$
246.8

$
155.0Operating StatisticsLakehead system:United States(1)


1,233


1,187


1,242


1,191Province of Ontario(1)


331


325


344


333Total Lakehead system deliveries(1)


1,564


1,512


1,586


1,524Barrel miles (billions)


105


101


317


301Average haul (miles)


730


723


729


723Mid-Continent system deliveries(1)


227


255


238


248North Dakota system:Trunkline


101


93


103


91Gathering


6


7


6


6Total North Dakota system deliveries(1)


107


100


109


97Total Liquids Segment Delivery Volumes(1)


1,898


1,867


1,933


1,869


---

Three months ended September 30, 2008 compared with three months ended September 30, 2007

Our Liquids segment accounted for $95.5 million of operating income during the three months ended September 30, 2008, an
increase of $37.9 million from the $57.6 million generated during the same period in 2007. The favorable results are attributable to increased volumes transported on our Liquids systems
coupled with tariff increases that went into effect during 2008, partially offset by higher power, operating and administrative costs, and depreciation. The majority of
the increase in delivery volumes is attributable to our Lakehead system; however, our North Dakota system also realized increased delivery volumes.

Operating
revenue for the three months ended September 30, 2008 increased by $71.1 million to $209.2 million from $138.1 million for the same period in 2007.
The increase in operating revenue is due to the following:



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The
increases in average tariffs on all three Liquids systems coupled with longer hauls and transportation of more heavy crude oil contributed approximately $57.0 million of
additional operating revenue. We implemented new tariffs in 2008 on our Lakehead system effective April 1, 2008 to reflect true-ups for the difference between estimated and actual
cost and throughput data for the prior year and our projected costs and throughput for 2008. The projected costs for 2008 include four projects: (1) the Southern Access mainline expansion,
(2) two Superior terminal tank projects,
(3) two Griffith terminal tank projects and (4) the Clearbrook Manifold project. We also implemented new tariffs on our North Dakota system effective January 1, 2008 that are
applicable for five years and are applied to all transportation routes with a destination of Clearbrook, Minnesota. Additionally, we increased the average tariffs on all three of our Liquids systems
in connection with the annual index rate ceiling adjustment that went into effect July 1, 2008. Additional discussion of these tariffs is provided below under the section labeled Regulatory MattersFERC
Transportation TariffsLiquids.

Average
delivery volumes on our Lakehead system increased approximately 3.4 percent, to 1.564 million Bpd during the three months ended September 30, 2008 from
1.512 million Bpd during the same period in 2007, contributing an additional $3.6 million to operating revenue. The increase in average deliveries on our Lakehead system is primarily
derived from increases of crude oil supplies from upstream production facilities associated with the ongoing development of the Alberta Oil Sands. However, crude oil supplies from western Canada were
lower than we expected due to two primary factors. First, Suncor, an oil sands producer in Alberta, Canada, had limited hydrotreating capacity in August and September of 2008 as well as an accident on
their oil sands pipeline both of which reduced production volumes. Second, Syncrude, another oil sands producer, is currently undergoing a maintenance turnaround that has resulted in lower production
volumes.

Included
in our transportation tariff is an allowance from our customers for the transportation of their crude oil. We recognize revenue for this allowance at the prevailing market price
for crude oil. The average prices of crude oil during the three months ended September 30, 2008 are substantially higher than the average prices for the same period of 2007. For example, the
average price of West Texas Intermediate crude oil has increased approximately 60 percent for the three months ended September 30, 2008 as compared with the same period in 2007. As a
result of the increase in crude oil prices, we experienced an approximate $8.2 million increase in allowance oil revenues.

Operating
and administrative expenses for the Liquids segment increased $18.1 million for the three months ended September 30, 2008, compared with the same period in 2007.
The increase in these costs is primarily attributable to the following:



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Oil
measurement adjustments occur as part of the normal operations associated with our Liquids systems. The three types of oil measurement adjustments that normally occur on our systems
include:



Power
costs increased $5.3 million in the three months ended September 30, 2008, compared with the same period in 2007, predominantly due to the higher delivery volumes
coupled with higher utility rates we are charged by our power suppliers. We have experienced a trend of increasing electricity rates from our power suppliers due to higher natural gas and coal costs.

The
increase in depreciation expense of $9.8 million is attributable to the additional assets we have placed in service during the last quarter of 2007 and the first three
quarters of 2008, including the Southern Access Expansion stage one assets that we placed in service during the second quarter of 2008 along with the assets placed into service on our North Dakota and
Mid-Continent systems.

Nine months ended September 30, 2008 compared with nine months ended September 30, 2007

Our Liquids segment accounted for $246.8 million of operating income during the nine months ended September 30, 2008,
representing a $91.8 million increase over the $155.0 million for the same period in 2007. The components comprising our operating income changed during the nine months ended
September 30, 2008 compared with the nine months ended September 30, 2007, primarily for the same reasons as noted above in our three-month analysis except that we had more favorable
experience with oil measurement adjustments for the nine months ended September 30, 2008.

Future Prospects Update for Liquids

We and Enbridge Inc. ("Enbridge") are actively working with our customers to develop transportation options that will allow
Canadian crude oil greater access to markets throughout the United States ("U.S."). The following discussion provides an update to the status of projects we and Enbridge are developing and should be
read in conjunction with the information included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Partnership Projects

Southern Access

We continue to progress on the second and final stage of the expansion project which will provide additional upstream pumping capacity
and a new pipeline from Delavan to Flanagan, Illinois. Construction of this stage of the project commenced on June 1, 2008. We expect to complete this phase of the expansion by the end of the
first quarter of 2009. Completion of the total Southern Access expansion project will create a 454-mile pipeline with approximately 400,000 Bpd of incremental capacity on our Lakehead
system.

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Table of Contents

Alberta Clipper

The Alberta Clipper project involves construction of a new 36-inch diameter, 1,000 mile heavy crude oil pipeline from
Hardisty, Alberta to Superior, generally within or adjacent to our and Enbridge's existing rights-of-way. We will construct approximately 330 miles of the new pipeline from the
International Border near Neche, North Dakota to Superior, a delivery connection at Clearbrook, Minnesota and an additional tank at Superior. Alberta Clipper will have an initial capacity of 450,000
Bpd and allows for expansions up to 800,000 Bpd by adding pump stations. In addition, complementary capacity on the Southern Access 42-inch pipeline from Superior to Flanagan will be
obtained by installing additional pump stations. We anticipate that our share of the construction cost for the United States segment of the project will approximate $1.2 billion. Alberta
Clipper will be a common carrier line fully integrated with the Enbridge/Lakehead mainline systems for tolling purposes. We and Enbridge are progressing with the project, which is expected to be in
service in mid-2010. We expect to begin construction on the U.S. leg of the project in the first quarter of 2009.

North Dakota

The United States Geological Survey, or USGS, completed an assessment of the undiscovered oil and associated natural gas resources of
the Upper DevonianLower Mississippi Bakken formation in the United States portion of the Williston Basin and has determined there to be 3.0 to 4.3 billion barrels of
technologically recoverable oil. Regional producers in the Williston basin areas of Montana and North Dakota have expressed interest in further expansion of pipeline capacity on our North Dakota
system. As a result, we have commenced an approximate $0.15 billion additional expansion consisting of upgrades to existing pump stations, additional tankage, as well as extensive use of drag
reducing agents ("DRA") that are injected into the pipeline. This expansion of our North Dakota system, referred to as Phase VI, is expected to increase system capacity to 161,000 Bpd from the
110,000 Bpd that is currently available. The commercial structure for this expansion is a cost-of-service based surcharge that will be added to the existing tariff rates. The
proposed tolling methodology is similar to the structure being used on the recently completed Phase V expansion project and was approved by the Federal Energy Regulation Commission ("FERC") in
October 2008.

Superior and Griffith Storage

Due to forecasted production increases of synthetic heavy crude oil that we anticipate will be transported on the Enbridge/Lakehead
mainline systems from Western Canada to Chicago, Illinois; we are constructing additional crude oil storage tanks at Superior and Griffith to accommodate the anticipated volumes. We are building two
tanks with operational capacity of approximately 205,000 barrels each. The Superior tank was completed in early September 2008 and the Griffith tank is on schedule to be completed in December 2008.

Trailbreaker (formerly Eastern PADD II Access)

We and Enbridge are jointly developing plans to provide access for western Canadian crude oil to refineries along the United States
Eastern Seaboard and the United States Gulf Coast ("U.S. Gulf Coast") via the marine terminal at Portland, Maine. The Trailbreaker project involves the expansion and reversal of existing facilities to
create a pipeline route to Portland that is ready for use in 2010. Commercial terms for the project are being negotiated which will be subject to regulatory approvals in both the United States and
Canada. Preliminary estimates indicate our portion of the project will approximate $0.3 billion (excluding capitalized interest).

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Table of Contents

Enbridge and Other Projects

Spearhead Pipeline

In another effort to provide shippers access to new markets, Enbridge acquired a pipeline that previously shipped crude oil from
Cushing, Oklahoma to Chicago. Enbridge reversed the pipeline, renamed it Spearhead, and began delivering Canadian crude oil to the major oil hub at Cushing in March 2006. Since then, the pipeline has
operated at or near its capacity of 125,000 Bpd. In the first half of 2007, Enbridge successfully concluded a binding open season for expansion of the pipeline to 190,000 Bpd, with binding commitments
for capacity of 30,000 Bpd. In December 2007, the FERC issued a favorable declaratory order effectively approving the tolling methodology and priority service for shippers with binding commitments.
Construction has commenced on the 65,000 Bpd expansion, which is expected to be in service in early 2009. The Spearhead pipeline is complementary to our Lakehead system as Western Canadian crude oil
is carried on our Lakehead system as far as Chicago, and then transferred to the Spearhead pipeline.

Southern Access Extension

In July 2006, Enbridge announced that it received support from shippers and the Canadian Association of Petroleum Producers ("CAPP")
for its 36-inch diameter Southern Access Extension pipeline from Flanagan to Patoka, Illinois. The extension will broaden the reach of the Enbridge/Lakehead mainline system to incremental
markets accessible from the Patoka hub. This project is being undertaken by Enbridge, however, we will benefit from the incremental volumes moving through our Lakehead system to reach this extension.
Enbridge filed a petition for declaratory order with the FERC in October 2007, which was denied on May 7, 2008. Enbridge is currently working with shippers to develop a new commercial structure
for the pipeline.

Southern Lights

Following completion of a successful open season in 2006, Enbridge initiated its Southern Lights project to construct a diluent
pipeline from Chicago to Edmonton, Alberta, Canada to meet the growing demand for crude oil diluent required to transport the heavy oil and bitumen (a thick, tar-like form of oil) being
produced in increasing volumes from the Alberta oil sands. The project involves the exchange of a 156-mile section of pipeline we own, referred to as Line 13, for a similar section of a
new pipeline to be constructed as part of the project. In addition, this project involves a reconfiguration of our light crude mainline system which will provide an additional 45,000 Bpd of effective
capacity at no cost to us. We expect to benefit from increased heavy crude oil shipments, which will be facilitated by the diluent line.

In
February 2008, the National Energy Board ("NEB") issued its approval and in May 2008 the Canadian Government also issued its Governor In Council ("GIC") approval for the Canadian
portion of the Southern Lights project. The GIC approval has been challenged through proceedings in the Federal Court of Canada by certain First Nations on the basis that the Canadian government
failed to adequately consult with affected First Nations. No hearing date has been set and the likelihood of success of this action is not determinable at this time. Enbridge has filed the majority of
necessary applications for the United States portion of the project with United States federal and state regulatory agencies. Enbridge filed a petition for declaratory order with the FERC setting
forth the rate structure for establishing tolls and the proposed swap of Line 13 discussed above, which the FERC approved in late December 2007. In conjunction with our Southern Access project, the
Southern Lights project has been allowed the right to exercise eminent domain for right-of-way in Illinois. Construction and right-of-way acquisition
related to this project continues in tandem with the Southern Access project. This project is expected to be placed in service in 2010.

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Table of Contents

United States Gulf Coast Joint Initiative

In August 2008, Enbridge and BP Pipelines (North America) Inc. ("BP") announced they are currently developing an initiative to
deliver incremental volumes of Canadian crude oil to the U.S. Gulf Coast. The initiative, as envisioned, involves the reversal of the BP #1 pipeline system between Flanagan and Cushing, as well as the
construction of a new pipeline between Cushing and Houston, Texas. The scope of the project provides for a pipeline system with over 150,000 Bpd of new capacity between Flanagan and Cushing and
approximately 250,000 Bpd of capacity between
Cushing and Houston. Enbridge is currently working with BP to develop commercial terms to present to a targeted list of potential shippers to solicit binding support prior to launching an open season
later this year. The target in-service date for this pipeline system is late 2012.

Texas Access Pipeline

The initiative discussed above aligns with the Enbridge strategy to pursue a staged approach to the U.S. Gulf Coast that matches supply
growth. The Texas Access pipeline will be brought to the forefront when a large volume solution to the U.S. Gulf Coast is required.

Natural Gas

The following tables set forth the operating results of our Natural Gas segment assets and approximate average daily volumes of our
major systems in millions of British Thermal Units per day ("MMBtu/d") for the periods presented:

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions)Operating ResultsOperating revenues

$
1,304.9

$
847.3

$
3,805.3

$
2,317.1Cost of natural gas


1,122.4


711.2


3,302.8


1,966.2Operating and administrative


83.8


68.1


235.8


190.3Depreciation and amortization


31.5


27.7


88.8


70.1Operating expenses


1,237.7


807.0


3,627.4


2,226.6Operating Income

$
67.2

$
40.3

$
177.9

$
90.5Operating Statistics (MMBtu/d)East Texas


1,443,000


1,158,000


1,431,000


1,162,000Anadarko


682,000


594,000


648,000


588,000North Texas


388,000


360,000


383,000


344,000UTOS


96,000


212,000


157,000


176,000MidLa


96,000


110,000


104,000


117,000AlaTenn


28,000


30,000


41,000


41,000Bamagas


99,000


148,000


79,000


126,000Other major intrastates


204,000


205,000


215,000


241,000Total(1)


3,036,000


2,817,000


3,058,000


2,795,000


---



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Three months ended September 30, 2008 compared with three months ended September 30, 2007

Our Natural Gas segment contributed $67.2 million of operating income for the three months ended September 30, 2008, an
increase of $26.9 million from the $40.3 million contributed in the corresponding period of 2007. The following discussion presents the primary factors affecting the operating income of
our Natural Gas business for the three months ended September 30, 2008 as compared with the same period of 2007:



Revenue
for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our
customers. We are exposed to fluctuations in commodity prices in the near term on 20 to 30 percent of the natural gas, NGLs and condensate we expect to receive as compensation for our services.
As a result of this unhedged commodity price exposure, our margins increase when the prices of these commodities are rising and decrease when the prices are declining. For the three months ended
September 30, 2008, we realized approximately $22 million of additional margin compared with the same period of 2007
primarily due to the higher prices we received from the sale of the unhedged natural gas, NGLs and condensate that we received in-kind as compensation for our services.

We
enter into derivative financial instruments to hedge 70 to 80 percent of our near-term exposure to commodity prices associated with the in-kind
compensation we receive for our services. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell
the processed natural gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate during that time. Many of these derivative financial instruments do not
qualify for hedge accounting which results in the derivative instrument being marked-to-market in our operating results. This accounting treatment produces unrealized
non-cash gains

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and
losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

The
operating income of our Natural Gas segment for the three months ended September 30, 2008 was positively affected by unrealized non-cash,
mark-to-market net gains of $36.6 million, representing an increase of $44.3 million from the $7.7 million of losses we recorded for the same period of
2007. During the three months ended September 30, 2008, declines in the forward and daily market prices of natural produced non-cash, mark-to-market gains in
our portfolio of derivative instruments. The declining price environment that was prevalent during the three months ended September 30, 2008, was not present during the same period of 2007. We
expect the net mark-to-market gains to be offset when the related physical transactions are settled. The following table depicts the affect that unrealized non-cash
mark-to-market gains and losses had on the operating results of our Natural Gas business for the three and nine months ended September 30, 2008 and 2007:

Three months ended
September 30,

Nine months ended
September 30,Derivative fair value gains (losses)

2008

2007

2008

2007(in millions)Natural Gas segmentHedge ineffectiveness

$
0.1

$
(0.5
)
$
(1.1
)
$
(0.2
)Non-qualified hedges


36.5


(7.2
)

42.5


(13.2
)Derivative fair value gains (losses)

$
36.6

$
(7.7
)
$
41.4

$
(13.4
)


The
increase in the average daily volume of our Natural Gas business is directly attributable to the significant investments we have made to expand the capacity and service capability of
our systems. We completed the following projects during 2008 and the last quarter of 2007, which have contributed to the increase in average daily volumes and operating results of our major natural
gas systems:



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With
the expansions we completed in 2007 and 2008 we are now able to provide additional gathering, processing, treating and transportation services for our customers which has
contributed to our volume growth in the third quarter of 2008. Volume and revenue growth is also the result of additional
wellhead supply contracts and continued robust drilling activity in the areas served by our Natural Gas business, primarily the Bossier Trend, Barnett Shale and Granite Wash areas. We expect the
volumes on our major natural gas systems to continue increasing throughout the year as a result of our investments to expand the capacity of our systems to provide gathering, processing and
transportation services to meet the needs of producers in the areas we serve.

During
the third quarter of 2008, we experienced operational disruptions to our onshore and offshore natural gas facilities as a result of hurricanes Gustav and Ike. Our facilities in
Texas and Louisiana sustained minimal physical damage from the hurricanes, although some of our natural gas systems had lower throughput and revenues in the month of September due to the inability of
third-party downstream facilities to receive deliveries of our natural gas and NGLs. These temporary disruptions curtailed our ability to gather unprocessed natural gas at our processing plants and
transport natural gas to markets in the Texas and Louisiana regions. Our current estimate of lost revenue associated with the hurricanes is $8 million to $9 million coupled with capital
and operating costs of $2 million to $3 million we expect to incur in the fourth quarter for repairs to our damaged facilities. We do not anticipate recovery of any significant amounts
of insurance for these losses. The majority of our facilities returned to normal operation by the end of September.

The
processing margins we derive from processing natural gas under keep-whole arrangements that exist within our East Texas, North Texas and Anadarko systems declined
52 percent during the third quarter of 2008 in relation to the same period of 2007. Operating income derived from keep-whole processing arrangements for the three months ended
September 30, 2008 was $18.4 million, representing a decrease of $19.6 million from the $38.0 million we produced for the same period in 2007. During the third quarter of
2008, NGL and crude oil prices began to decline faster than natural gas prices, which have the effect of reducing revenue we derive from our processing assets less the cost of natural gas purchased
for processing. In addition to the affect that changing prices have had on the processing margins we derive from processing natural gas under keep-whole arrangements, we continue to
experience a trend of replacing or renegotiating some of our existing keep-whole contracts with percentage of liquids, or POL, type contracts and other similar arrangements. This trend may
reduce our exposure to commodity price risk along with a portion of the operating income we derive from processing natural gas under keep-whole arrangements.

Despite
the higher average daily prices for natural gas and NGLs we received during the three months ended September 30, 2008 relative to the same period of 2007, the daily prices
for natural gas and NGLs at September 30, 2008 were lower than the prices for these commodities at June 30, 2008. The lower commodity prices at September 30, 2008 produced approximately
$4.8 million of revaluation losses with respect to our in-kind natural gas imbalances, as well as approximately $2.2 million of non-cash charges to reduce the cost basis of our natural
gas inventory to fair market value. We did not experience similar fluctuations in commodity prices for the three months ended September 30, 2007.

Operating
and administrative costs of our Natural Gas segment were $15.7 million greater for the three months ended September 30, 2008 than the three months ended
September 30, 2007, primarily as a result of increased workforce-related costs associated with the expansion of our systems, maintenance activities and other costs that are mostly variable with
volumes. Our general partner charges us the costs associated with employees and related benefits for personnel that are assigned to us or otherwise
provide us with managerial and administrative services. The portion of compensation and related costs we are charged is dependent upon such items as estimated time spent, miles of pipe and headcount.
In addition we have experienced an increase in outside contract labor cost, given the high demand and competitive rates within our industry as a result of pipeline expansions across the areas we
serve.

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Materials, supplies and other costs along with repair and maintenance costs were higher predominantly due to the increase in volumes and expansion of our natural
gas systems. Repair and maintenance costs include compressor maintenance, downtime for routine and unscheduled maintenance, pipeline integrity costs and other similar items that have increased with
the expansion of our natural gas systems. We expect workforce related costs in addition to materials, supplies and other costs to increase in relation to the increase in volumes of natural gas
services we provide.

Depreciation
expense for our Natural Gas segment was higher in the third quarter of 2008 as compared the third quarter of 2007, as a result of the capital projects completed and placed
in-service during the first nine months of 2008 and the last quarter of 2007. We expect deprecation expense will be higher in 2008 as a result of the projects we completed and placed in
service throughout 2007 and the first half of 2008.

Nine months ended September 30, 2008 compared with nine months ended September 30, 2007

Our Natural Gas segment accounted for $177.9 million of operating income during the nine months ended September 30, 2008,
representing an $87.4 million increase over the $90.5 million for the same period in 2007. The components comprising our operating income changed favorably during the nine months ended
September 30, 2008 compared with the nine months ended September 30, 2007, primarily for the same reasons noted above in our three-month analysis except for those items described below.

The
operating income of our Natural Gas business derived from processing increased by approximately $30 million during the nine months ended September 30, 2008, as compared
with the same period in 2007, despite the impact of the hurricanes and the declining price environment that occurred late in the third quarter of 2008 as discussed above under our three month
analysis. For a majority of the nine months ended September 30, 2008, we have benefitted from a favorable pricing environment for the production of NGLs. NGL prices were high relative to
natural gas prices during most of the nine month period of 2008 providing a favorable environment for the production of NGLs from our processing assets. We have also benefitted from the processing
capacity we added on our Anadarko system in April 2007 of approximately 120 MMcf/d and the 75 MMcf/d we added on our North Texas system in the second half of 2007. The added processing
capacity provided us with the ability to generate additional processing margin from the NGLs we produced during the first nine months of 2008. Our Zybach processing plant has also continued to operate
at expected levels during the first nine months of 2008, which compares favorably with the same period of 2007 when we experienced operational issues that reduced processing margins by approximately
$11 million.

Operating
income for the nine months ended September 30, 2008 was positively affected by the unrealized non-cash, mark-to-market net gains of
$41.4 million from our derivative activities, which is approximately $54.8 million more than the $13.4 million of losses we recorded for the same period of 2007. We expect the net
mark-to-market gains and losses to be offset when the related physical transactions are settled.

Future Prospects Update for Natural Gas

Significant liquidity tightening and volatility in the capital markets will necessitate a less aggressive capital program in our
natural gas business in the near term. During this period of volatility we will continue to focus our efforts primarily on development of our existing pipeline systems. We continue to evaluate
strategic opportunities to further expand the service capabilities of our existing system and we may pursue opportunities to divest any non-strategic natural gas assets as conditions
warrant.

Results
of our natural gas gathering and processing business depend upon the drilling activities of natural gas producers in the areas we serve. During the third quarter of 2008,
increased production from active drilling in the areas where our gathering systems are located has contributed to our volume growth. Recent announcements by natural gas producers forecasting reduced
exploration and development

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programs
could impact the rate of growth in our natural gas assets. However, we believe our assets are located in three areas where producers are likely to remain active due to the higher probability
of success associated with resource developments in the East Texas, North Texas and Anadarko regions. We believe this factor should temper the impact of lower natural gas production drilling programs
on the results of our Natural Gas business.

Milsap Plant

We plan to purchase and construct a 55 MMcf/d cryogenic processing plant and associated piping, which we refer to as the Millsap
Plant Project, to accommodate Barnett Shale growth opportunities in North Texas. The design will incorporate flexibility to expand the inlet capacity of the plant to 75 MMcf/d (through
expansion of inlet and residue compression) should volume growth exceed our expected forecast. We expect the cost to complete construction to approximate $100 million with an in service date
late in the first quarter of 2010.

Shelby County Loop and Compression

We commenced construction during the third quarter of 2008 to add compression at the Carthage Hub and on the Shelby lateral sections of
our East Texas system. We have also initiated construction to increase the capacity of the East Texas system in the area by installing approximately 26 miles of 20-inch pipeline. We
expect to complete this project during 2009 at an approximate cost of $60 million.

Marketing

The following table sets forth the operating results of our Marketing segment assets for the periods presented:

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions)Operating ResultsOperating revenues

$
1,298.6

$
725.5

$
3,819.7

$
2,444.9Cost of natural gas


1,285.1


719.6


3,817.8


2,424.5Operating and administrative


2.5


2.3


7.1


5.8Depreciation and amortization


0.4


0.4


1.3


1.2Operating expenses


1,288.0


722.3


3,826.2


2,431.5Operating Income (Loss)

$
10.6

$
3.2

$
(6.5
)
$
13.4


A
majority of the operating income of our Marketing segment is derived from selling natural gas received from producers on our Natural Gas segment pipeline assets to customers who need
natural gas. As a result of our natural gas system expansions and other initiatives, our Marketing business now has access to several additional downstream natural gas pipelines, which it can use to
transport natural gas to primary markets where it can be sold at more favorable prices.

We
adopted the provisions of SFAS No. 157 effective January 1, 2008, which did not affect the operating results of our Marketing business, but did expand the disclosures we
provide about how we determine the fair value of our derivative instruments. Refer to the discussions included in Notes 9 and 10 of our consolidated financial statements included in
Item 1 of this report and also to the discussions below under "Derivative Activities" and the "Quantitative and Qualitative Disclosures about Market Risk" we include in Item 3 of this
report for more information about our derivative activities.

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Three months ended September 30, 2008 compared with three months ended September 30, 2007

The operating income of our Marketing segment increased to $10.6 million for the third quarter of 2008 from $3.2 million
for the corresponding period in 2007. Included in operating income for the third quarter of 2008 are approximately $11.0 million of unrealized, non-cash,
mark-to-market gains associated with derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133, as compared with the
$2.9 million of unrealized mark-to-market gains for the same period of 2007. During the three months ended September 30, 2008, declines in the forward and daily
market prices of natural gas produced non-cash, mark-to-market gains in our portfolio of derivative instruments in excess of those produced during the same period
of 2007. We expect these net mark-to-market gains to be offset when the related physical transactions are settled.

Operating
income for the three months ended September 30, 2008 was also negatively affected by non-cash charges of $6.1 million we recorded to reduce the cost
basis of our natural gas inventory to fair market value at September 30, 2008, which is $3.1 million more than the $3.0 million non-cash charge we recorded for the
same period of 2007. The average daily price of natural gas as published by Platt's Gas Daily for Henry Hub was approximately $7.23 per MMBtu for the month of September 2008, a decline from $12.60 per
MMBtu for the month of June 2008. As a result of this decline in the price of natural gas inventory at our storage locations from June 30, 2008 to September 30, 2008, the weighted
average cost of our natural gas inventory at September 30, 2008 exceeded the market price of natural gas by approximately $6.1 million. Due to our hedging structures, we expect that a
majority of these charges will be offset by future financial transactions that will settle at the time the natural gas inventory is sold.

The
operating and administrative expenses of our Marketing business were slightly more in the quarter ended September 30, 2008 as compared with the same period of 2007 due to
additional workforce
related costs associated with the employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services.

Nine months ended September 30, 2008 compared with nine months ended September 30, 2007

Operating income of our Marketing segment declined to a loss of $6.5 million for the nine month period ended
September 30, 2008 from income of $13.4 million for the corresponding period in 2007. Included in the operating loss for the first nine months of 2008 are approximately
$23.9 million of unrealized, non-cash, mark-to-market losses associated with derivative financial instruments that do not qualify for hedge accounting
treatment under SFAS No. 133, compared to the $4.0 million of unrealized mark-to-market losses for the comparable period of 2007. The unrealized,
mark-to-market losses for the nine months ended September 30, 2008 result from increases in the forward and daily market prices of natural gas from December 31,
2007. We expect these net mark-to-market losses to be offset when the related physical transactions are settled.

The
operating and administrative expenses of our Marketing business are slightly more in the nine months ended September 30, 2008 as compared with the same period of 2007 due to
additional workforce related costs associated with the employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services.

Corporate

Interest expense was $50.7 million and $129.7 million for the three and nine months ended September 30, 2008,
compared with $23.4 million and $70.2 million for the corresponding periods in 2007. The increases are primarily the result of higher weighted average debt balance associated with the
following debt issuances:



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Our
weighted average interest rate is 6.3% for the three months and 6.0% for the nine months ended September 30, 2008 as compared with our weighted average interest rates of 6.0%
and 5.9% for the same periods in 2007.

Further
contributing to the increase in interest expense is the $4.0 million decrease in interest capitalized to our construction projects in the three months ended
September 30, 2008 from the same period in 2007. Conversely, the increase in interest expense in the first nine months of 2008 was offset by an additional $5.6 million of capitalized
interest when compared to the same period in 2007. For the three and nine months ended September 30, 2008 and 2007, our interest cost is comprised of the following:

Three months ended
September 30,

Nine months ended
September 30,2008

2007

2008

2007(unaudited; in millions)Interest expense

$
50.7

$
23.4

$
129.7

$
70.2Interest capitalized


6.2


10.2


31.2


25.6Interest cost incurred

$
56.9

$
33.6

$
160.9

$
95.8


LIQUIDITY AND CAPITAL RESOURCES

Disruption to Functioning of Capital Markets

Multiple events during 2008 involving numerous financial institutions have effectively restricted current liquidity within the capital
markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to
the financial sector, capital markets currently remain constrained. We expect that our ability to issue debt and equity at prices that are similar to offerings in recent years will be limited over the
next three to six months and possibly longer should capital markets remain constrained. Although we intend to move forward with our planned internal growth projects, we may revise the timing and scope
of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to our unitholders from our expansion activities may be muted by substantial cost of capital
increases during this period.

General

We believe that our ability to generate cash flow is sufficient to meet our current and future operating needs. Our primary operating
cash requirements consist of normal operating expenses, core maintenance activities, distributions to our partners and payments associated with our derivative activities. We expect to fund our current
and future short-term cash requirements from our operating cash flows. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued
under our Credit Facility.

Our
current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses with less focus on acquisitions. Our need for investment capital to fund
our expansion projects, make acquisitions of new assets and businesses and to retire maturing or callable debt obligations is expected to be funded from several sources. We anticipate initially
funding long-term cash requirements for expansion projects and acquisitions first from operating cash flows, second, from borrowings under our commercial paper program and/or our Credit
Facility, and lastly, from borrowings under our $500 million revolving credit agreement with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge Inc. Likewise, we
anticipate initially retiring our maturing and callable debt with similar borrowings on these existing

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facilities.
We expect to obtain permanent financing through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities. Our
ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial
condition and our credit rating at the time.

Capital Resources

Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private
equity and credit markets to obtain the capital necessary to fund these projects. Although we have generated in excess of $2.2 billion over the past two years through the issuance of a balanced
combination of debt and equity securities to fund our expansion projects, our ability to access these markets to obtain permanent financing over the next three to twelve months is likely to be limited
due to prevailing market conditions. Our planned internal growth projects continue to require us to bear the cost of constructing these new assets before we begin to realize a return on them. As a
result, we will continue to be opportunistic in our approach to funding the remaining expenditures from additional issuances of our capital and long-term debt.

In
March 2008, we obtained approximately $221.8 million of cash from the public issuance and sale of 4.6 million of our Class A common units at a price to the public
of $49.00 per unit, which consisted of $217.2 million of net proceeds, after payment of underwriters' discounts, commissions and offering expenses and a contribution of $4.6 million from
our general partner to maintain its two percent general
partner interest. Additionally, in early April 2008, we completed the private issuance and sale of our $400 million Notes due 2018 and our $400 million Notes due 2038 for net proceeds of
approximately $790.2 million, after payment of initial purchasers' discounts and offering expenses. The Notes due 2018 bear interest at the rate of 6.50% and the Notes due 2038 bear interest at
the rate of 7.50%. We used a portion of the proceeds from these offerings to repay outstanding issuances of commercial paper and borrowings under our Credit Facility, which we had previously used to
finance a portion of our capital expansion projects. We temporarily invested the remaining proceeds for use in future periods to fund additional expenditures under our capital expansion programs.

Available Credit

Two primary sources of our liquidity are provided by the commercial paper market and our Credit Facility. We have a $600 million
commercial paper program that is supported by our long-term Credit Facility, which we access primarily to provide temporary financing for our operating activities, capital expenditures and
acquisitions, at rates that in the past have been generally more competitive than the rates available under our Credit Facility. In addition to our Credit Facility and commercial paper program, we
have access to a $500 million unsecured three year revolving credit agreement from Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge Inc.

Credit
markets in the United States and around the world remain constrained due to a lack of liquidity and confidence in a number of financial institutions. Investors continue to seek
perceived safe investments in securities of the United States government rather than corporate issues. Although the credit ratings assigned to our senior unsecured debt securities by the nationally
recognized statistical ratings organizations are considered "investment grade," we may at times experience difficulty accessing the commercial paper and long-term credit markets due to
prevailing market conditions. Additionally, existing constraints in the commercial paper and credit markets may increase the rates we are charged for utilizing these markets. Notwithstanding the
continuing weakness in the United States credit markets, we expect that our available liquidity is sufficient to meet our operating and capital requirements into 2009 and for the foreseeable future.

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Credit Facility

A subsidiary of Lehman Brothers Holdings, Inc. ("Lehman"), Lehman Brothers Bank, FSB ("Lehman BB") is one of the
committed lenders under our Credit Facility. On September 15, 2008, Lehman filed a petition under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern
District of New York. Lehman BB has declined requests to honor its commitment to lend up to $82.5 million under our Credit Facility, effectively reducing the amount available to us under
our Credit Facility to $1,167.5 million. We are working with other financial institutions to assume Lehman BB's commitment. The remaining lenders under our Credit Facility continue to
honor our requests for funding and we believe the amounts available to us under our Credit Facility will continue to provide us with sufficient liquidity to meet our working capital needs.

The
amounts we can borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit
outstanding. At September 30, 2008, we had $386.2 million outstanding under our Credit Facility at a weighted average interest rate of 3.82% and letters of credit totaling
$101.2 million.

At
September 30, 2008, we could borrow $490.1 million under the terms of our Credit Facility, determined as follows:

September 30,
2008(in millions)Total credit available under Credit Facility

$
1,250.0Less:

Amounts outstanding under Credit Facility


(386.2
)Balance of letters of credit outstanding


(101.2
)Principal amount of commercial paper issuances


(190.0
)Lehman Brothers Bank, FSB commitment


(82.5
)Total amount we could borrow at September 30, 2008

$
490.1


In
March 2008, we requested and received approval from the parties named as lenders to our Credit Facility for a one year extension of the maturity date of the Credit Facility from
April 4, 2012 to April 4, 2013.

Commercial Paper Program

At September 30, 2008, we had $190 million in principal amount of commercial paper outstanding, with unamortized discount
of $0.5 million, at a weighted average interest rate of 3.19%, before the effect of our interest rate hedging activities. Under our commercial paper program, we had net repayments of
approximately $79.4 million during the nine months ended September 30, 2008, which include gross issuances of $1,603.9 million and gross repayments of $1,683.3 million. At
September 30, 2008, we could issue an additional $410 million in principal amount under our commercial paper program. The commercial paper we can issue is limited by the credit available
under our Credit Facility.

EUS Credit Agreement

In addition to our Credit Facility and commercial paper program, we have access to an unsecured three year revolving credit agreement
with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge Inc. (the "EUS Credit Agreement"). The EUS Credit Agreement provides us with access to an additional $500 million
of financing on substantially the same terms as our Credit Facility and matures in December 2010. The amounts available to us under the EUS Credit Agreement remain undrawn at September 30, 2008
and available for our use.

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Table of Contents

The credit markets, including the commercial paper markets in the United States, have recently experienced adverse conditions. Continuing volatility in the
capital markets may increase costs associated with issuing commercial paper or other debt instruments or affect our ability to access those markets. Notwithstanding these adverse market conditions, we
currently believe that current cash and cash generated by operations, together with access to external sources of funds as described above, will be sufficient to meet our operating and capital needs
in the foreseeable future.

Cash Requirements for Future Growth

Capital Spending

We expect to make significant expenditures for the construction of additional natural gas and crude oil transportation infrastructure
over the next three years. In 2008, we expect to spend approximately $1.6 billion on these and other projects with the expectation of realizing additional cash flows as projects are completed
and placed in service. Our ability to fund these expenditures is dependent upon our ability to access the capital necessary to finance the construction of these facilities. Capital markets in the
United States and abroad are constrained and as a result we may revise the timing and scope of these projects as necessary to adapt to existing markets and economic conditions.

Forecasted Expenditures

We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are those
expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which is worn, obsolete or completing its
useful life. Enhancement expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues, and
enable us to respond to governmental regulations and developing industry standards.

We
estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the capital necessary
to accomplish our growth objectives. The following table sets forth our estimates of capital required for system enhancement and core maintenance expenditures through December 31, 2008.
Although we anticipate making the indicated expenditures, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier
prices or poor economic conditions. Additionally, estimates may change as a result of decisions made at a later date to revise the scope of a project. We made capital expenditures of
$1.0 billion, including $49.3 million for core maintenance activities, during the nine months ended September 30, 2008.

For
the full year of 2008, we anticipate our capital expenditures to approximate the following in billions:

System enhancements

$
0.5Core maintenance activities


0.1Southern Access expansion


0.8Alberta Clipper


0.2$
1.6


Major Construction Projects

The following table includes our active major construction projects and additional information regarding our estimated construction
cost, actual expenditures through September 30, 2008, the incremental capacity that will become available upon completion of the project and the periods during

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which
we expect to complete the construction. The projected amounts included in this table may change due to modifications of the scope of the project, increases in materials and construction costs
and other factors that are outside of our direct control.

Capital Expenditures

Estimated Incremental CapacityEstimated Total
Cost

Actual
Expenditures
through
September 30,
2008

Storage(1)

Oil(2)

Natural Gas(3)

Expected Completion(in billions)Southern Access expansion (Lakehead)

$
2.1

$
1.7





400




2009Clarity (East Texas)


0.6


0.6








700

2008Alberta Clipper


1.2


0.1





450




Mid-2010North Dakota phase 6 expansion


0.2








50




Early 2010Griffith and Superior storage tanks


0.1





1,220







2008Trailbreaker


0.3













2012Total

$
4.5

$
2.4


1,220


900


700


---

At September 30, 2008, we have approximately $573.2 million in outstanding purchase commitments for materials and services
associated with our capital projects for the construction of assets that we expect to settle during the remainder of 2008 and into 2009. However, we will incur additional commitments as our capital
projects continue to progress.

Including
major expansion projects and excluding acquisitions, ongoing capital expenditures are expected to be significant over the next three years due to our Southern Access expansion
and Alberta Clipper projects. Core maintenance capital is also anticipated to increase over that period of time due to growth in our pipeline systems and aging of infrastructure.

We
anticipate funding the system enhancement capital expenditures temporarily through the issuance of commercial paper or borrowing under the terms of our Credit Facility, with permanent
debt and equity funding being obtained when appropriate. Core maintenance expenditures are expected to be funded by operating cash flows.

We
expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our
pipeline systems.
Expenditure levels have continued to increase as pipelines age and require higher levels of inspection or maintenance; however, these are viewed to be consistent with industry trends.

Derivative Activities

We use derivative instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to
mitigate the volatility of our cash flows and manage the risks associated with market fluctuations in commodity prices. Based on our risk management policies, all of our derivative instruments are
employed in connection with an underlying asset, liability or anticipated transaction and are not entered into with the objective of speculating on commodity prices.

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The
following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative instruments at September 30, 2008:

Notional

2008

2009

2010

2011

2012

2013

Total(dollars, in millions)SwapsNatural gas(1)


314,776,128

$
(21.8
)
$
(42.0
)
$
(41.1
)
$
(33.2
)
$
(7.0
)
$
1.1

$
(144.0
)NGL(2)


8,029,873


(18.5
)

(43.2
)

(7.0
)

(0.5
)

4.6





(64.6
)Crude(2)


1,345,324


(5.3
)

(11.4
)

(7.9
)

(7.6
)

(5.8
)

1.1


(36.9
)Options-callsNatural gas(1)


1,187,000


(0.3
)

(1.4
)

(1.5
)

(1.4
)







(4.6
)NGL(2)


9,486




















Options-putsNatural gas(1)


1,310,000


0.6

















0.6NGL(2)


1,087,300


0.4


1.0


2.3


1.5


2.6





7.8Totals




$
(44.9
)
$
(97.0
)
$
(55.2
)
$
(41.2
)
$
(5.6
)
$
2.2

$
(241.7
)


---

Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2008 was $473.2 million, an increase of
$55.3 million from the $417.9 million generated during the same period in 2007. The increase in operating cash flow is directly attributable to the improved operating performance of our
Liquids and Natural Gas systems. Although net cash provided by operating activities increased, cash flows associated with changes in our working capital accounts for the nine months ended
September 30, 2008 were lower than the same period of 2007 due to the general timing differences in the collection on and payment of our current and related party accounts.

Investing Activities

We used $294.8 million less in our investing activities during the nine months ended September 30, 2008 in relation to
the same period in 2007. The decrease is primarily attributable to the $315.8 million reduction of amounts spent in the first nine months of 2008 on our construction projects as compared to the
same period of 2007. The decrease in the amounts spent on our construction projects is primarily attributable to completion of our Clarity project and the first stage of our Southern Access expansion
project.

Financing Activities

Net cash provided by financing activities during the nine months ended September 30, 2008 was $707.1 million, compared
with $920.9 million for the corresponding period in 2007. The reduction in the amount of cash provided by financing activities is due primarily to the lower amount of cash generated from our
unit issuances in the first nine months of 2008 when compared to the same period in 2007. Net cash provided by financing activities for the nine months ended September 30, 2008 is attributable
to the following:



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The
increase in cash raised from both our unit and debt issuances is partially offset by the following:



For
the nine months ended September 30, 2008 we had gross borrowings of $2,131.3 million under our Credit Facility and gross repayments of $2,145.0 million,
including $490.0 million of non-cash borrowings and repayments. Under our commercial paper program we had gross issuances of $1,603.9 million and gross repayments
$1,683.3 million during the first nine months of 2008.

OFF-BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements.

SUBSEQUENT EVENTS

Distribution to Partners

On October 13, 2008, the Board of Directors of Enbridge Management declared a distribution payable to our partners on
November 14, 2008. The distribution will be paid to unitholders of record as of November 6, 2008, of our available cash of $108.8 million at September 30, 2008, or $0.990
per common unit. Of this distribution, $74.9 million will be paid in cash, $14.3 million will be distributed in i-units to our i-unitholder, $18.9 million
will be distributed in Class C units to the holders of our Class C units and $0.7 million will be retained from the General Partner in respect of the i-unit and
Class C unit distributions.

REGULATORY MATTERS

FERC Transportation TariffsLiquids

Effective July 1, 2008, we increased our rates for transportation on our Lakehead, North Dakota and Ozark systems in accordance
with the indexed rate ceilings allowed by the FERC. In March 2006, the FERC determined that the Producer Price Index For Finished Goods plus 1.3 percent (PPI + 1.3 percent)
should be the oil pricing index for a five year period ending July 2011. The index is used to establish rate ceiling levels for oil pipeline rate changes. For our Lakehead system, indexing only
applies to the base rates, and does not apply to the SEP II, Terrace and Facilities surcharges. Effective July 2008, we increased the base tariff rates on our Lakehead system by an average of
8.2 percent to equal the indexed ceiling level allowed under the FERC's indexing methodology. On our Lakehead system, the new average rate for crude oil movements from the International Border
near Neche, North Dakota to Chicago, Illinois is $1.26 per barrel, which reflects a $0.05 per barrel increase over the rates filed effective April 1, 2008. In addition to the rates on our
Lakehead system, we increased the transportation rates on our North Dakota and Ozark systems
5.2 percent. The tariff rates for our Lakehead, North Dakota and Ozark systems are at the ceiling levels allowed under the FERC methodology.

Effective
April 1, 2008, we filed our annual tariff with the FERC to reflect true-ups for the difference between estimates and actual cost and throughput data for the
prior year and our projected costs and throughput for 2008. The projected costs for 2008 include four projects including the first stage of the Southern Access mainline expansion, two Superior and
Griffith terminal tank projects and the Clearbrook Manifold project. This filing increased the average tariff for crude oil movements from the Canadian

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border
to Chicago, Illinois, by approximately $0.34 per barrel, to an average of approximately $1.21 per barrel. We began to realize revenues in relation to this increased surcharge as crude oil is
delivered from our pipeline, generally the month following the effective date of the tariff.

OTHER MATTERS

We amended our limited partnership agreement to modify the mechanism by which the capital accounts of all our partners are maintained
when our general partner's incentive distribution rights are considered in determining the fair market value of the Partnership's assets in the event of a follow-on offering of our common
units. We do not expect the amendment to materially change the amount of net taxable income or loss allocated to our unitholders or the economic rights of our unitholders as compared with the
allocations or economic rights of our general partner.

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the Financial Accounting Standard Board, or FASB, issued Statement No. 161,Disclosures
about Derivative Instruments and Hedging Activities, which is effective for fiscal years and interim periods beginning after November 15, 2008. The statement requires
qualitative disclosures about a company's strategies and objectives for using derivatives, quantitative disclosures about fair value gains and losses on derivatives, and disclosures of
credit-risk-related contingent features in derivative instruments. We do not anticipate adopting the provisions of this pronouncement early. We do not expect our adoption of
this pronouncement to have a material affect on our financial statements other than modifications to our existing derivative disclosures to conform to the requirements set forth in the statement.

Calculation of Earnings Per Unit

In March 2008, the Emerging Issues Task Force, or EITF reached consensus on EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement
No. 128 to Master Limited Partnerships. The pronouncement prescribes the
manner in which a master limited partnership, or MLP, should allocate and present earnings per unit using the two-class method set forth in FASB Statement No. 128, Earning per Share. Under the
two-class method, current period earnings are allocated to the general partner (including any embedded
incentive distribution rights) and limited partners according to the distribution formula for available cash set forth in the partnership agreement. To the extent the partnership agreement does not
explicitly limit distributions to the general partner; any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for
available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited
partners based on their respective sharing of losses specified in the partnership agreement for the period. EITF 07-4 is to be applied retrospectively for all financial statements
presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not
permitted. We expect to adopt EITF 07-4 for our quarter ending March 31, 2009. We are currently evaluating the affect this pronouncement will have on our present computation
of earnings per unit.

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Item 3.    Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with the information presented in our Annual Report on Form 10-K for the
year ended December 31, 2007, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that
information other than as presented below.

Our
net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGLs, condensate and fractionation margins (the relative price
differential between NGL sales and the offsetting natural gas purchases). Our exposure to commodity price risk exists within our
Natural Gas and Marketing segments. To mitigate the volatility of our cash flows, we use derivative instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar
characteristics) to manage the risks associated with market fluctuations in commodity prices. Based on our risk management policies, all of our derivative instruments are employed in connection with
an underlying asset, liability or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

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The
following tables provides information about our derivative instruments at September 30, 2008 and December 31, 2007, with respect to our commodity price risk management
activities for natural gas and NGLs, including condensate:

At September 30, 2008

At December 31, 2007Wtd. Average Price(2)

Fair Value(3)

Fair Value(3)Commodity

Notional(1)

Receive

Pay

Asset

Liability

Asset

LiabilityContract maturing in 2008SwapsReceive variable/pay fixed

Natural Gas


8,542,547

$
6.20

$
7.62

$
0.9

$
(13.0
)
$
7.6

$
(14.5
)NGL


30,000


88.10


87.44


0.1


(0.1
)




Receive fixed/pay variable

Natural Gas


7,670,290


6.68


6.72


8.2


(8.6
)

10.3


(39.8
)NGL


1,452,036


42.37


55.24


0.5


(19.0
)




(98.9
)Crude Oil


137,824


61.68


100.48





(5.3
)




(17.7
)Receive variable/pay variable

Natural Gas


51,956,969


6.80


6.98


6.2


(15.5
)

7.0


(3.5
)OptionsCalls (written)

Natural Gas


92,000


4.31


7.62





(0.3
)




(1.3
)Calls (purchased)

NGL


9,486


53.53


53.19











Puts (purchased)

Natural Gas


215,000


9.05


6.85


0.6








NGL


136,896


57.41


46.47


0.4





0.1


Contract maturing in 2009SwapsReceive variable/pay fixed

Natural Gas


16,187,681

$
7.47

$
8.18

$
3.4

$
(14.5
)
$
5.5

$
(1.6
)NGL


176,870


60.94


63.69


0.1


(0.6
)




Receive fixed/pay variable

Natural Gas


18,471,215


6.43


7.88


12.4


(38.4
)

1.2


(41.8
)NGL


3,735,045


46.19


57.94


5.9


(48.6
)




(43.6
)Crude Oil


354,625


69.29


102.46





(11.4
)




(7.2
)Receive variable/pay variable

Natural Gas


104,153,403


7.68


7.73


5.8


(10.7
)

2.9


(1.8
)OptionsCalls (written)

Natural Gas


365,000


4.31


8.15





(1.4
)




(1.5
)Puts (purchased)

Natural Gas


365,000


8.15


3.40











NGL


566,072


55.51


46.00


1.9


(0.9
)

0.6


Contract maturing in 2010SwapsReceive variable/pay fixed

Natural Gas


3,713,769

$
8.11

$
7.55

$
4.5

$
(2.6
)
$
4.4

$
NGL


45,625


50.59


57.63





(0.3
)




Receive fixed/pay variable

Natural Gas


10,048,870


4.40


8.45


0.7


(39.1
)




(38.0
)NGL


1,513,655


49.12


53.78


7.5


(14.2
)




(13.8
)Crude Oil


332,150


79.29


104.75


1.3


(9.2
)




(4.4
)Receive variable/pay variable

Natural Gas


64,375,000


8.30


8.38


0.7


(5.3
)

1.5


(0.7
)OptionsCalls (written)

Natural Gas


365,000


4.31


8.57





(1.5
)




(1.4
)Puts (purchased)

Natural Gas


365,000


8.57


3.40











NGL


172,280


59.23


53.37


2.3








Contract maturing in 2011SwapsReceive variable/pay fixed

Natural Gas


1,598,755

$
8.37

$
6.97

$
3.3

$
(1.3
)
$
3.2

$
Receive fixed/pay variable

Natural Gas


7,955,920


3.63


8.53





(35.3
)




(34.1
)NGL


581,810


55.84


56.81


4.1


(4.6
)




(4.3
)Crude Oil


228,125


68.36


105.35





(7.6
)




(3.4
)Receive variable/pay variable

Natural Gas


15,885,000


8.63


8.62


0.5


(0.4
)

0.1


OptionsCalls (written)

Natural Gas


365,000


4.31


8.54





(1.4
)




(1.4
)Puts (purchased)

Natural Gas


365,000


8.54


3.40











NGL


83,220


63.34


51.53


1.5








Contract maturing in 2012SwapsReceive variable/pay fixed

Natural Gas


941,709

$
8.33

$
8.72

$
0.9

$
(1.2
)
$
0.9

$
NGL


36,600


50.28


55.58





(0.2
)




Receive fixed/pay variable

Natural Gas


1,456,000


3.57


9.05





(7.0
)




(6.8
)NGL


458,232


70.56


58.26


4.8








Crude Oil


219,600


74.85


105.75





(5.8
)




(1.9
)Receive variable/pay variable

Natural Gas


1,089,000


8.20


7.90


0.3








OptionsPuts (purchased)

NGL


128,832


66.80


54.10


2.6








Contract maturing after 2012SwapsReceive fixed/pay variable

Natural Gas


730,000

$
9.83

$
8.00

$
1.1

$


$


$
Crude Oil


73,000


124.05


106.12


1.1











---

47

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Table of Contents

Our
credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contract. When
appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

The
table below summarizes our derivative balances by counterparty credit quality in millions of dollars (negative amounts represent our net obligations to pay the counterparty).

September 30,
2008

December 31,
2007(in millions)Counterparty Credit Quality*AAA

$


$
AA


(164.0
)

(298.3
)A


(76.4
)

(47.2
)Lower than A





Total

$
(240.4
)
$
(345.5
)






Item 4.   Controls and Procedures

We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to
record, process, summarize and report the information required in our annual and quarterly reports under the Securities Exchange Act of 1934. Our management has evaluated the effectiveness of our
disclosure controls and procedures as of September 30, 2008. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls
and procedures are effective to accomplish their purpose. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain
treasury, accounting and other services on our behalf. We have not made any changes that materially affected, or are reasonably likely to materially affect, our internal control over financial
reporting during the three months ended September 30, 2008.

48

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Table of Contents

PART IIOTHER INFORMATION

Item 1.    Legal Proceedings

Refer to Part I, Item 1. Financial statements, Note 9, which is incorporated herein by reference.

Item 1A.    Risk Factors

The risk factors presented below update and should be considered in addition to the risk factors previously disclosed in our Annual
Report on Form 10-K for the fiscal year ended December 31, 2007.

Our ability to access the credit and capital markets on attractive terms to obtain funding for our capital projects may be limited due to the deterioration of these markets.

Global financial markets and economic conditions have been, and continue to be, weak and volatile which has caused a substantial
deterioration in the credit and capital markets. These conditions, along with significant write-offs in the financial services sector and the re-pricing of credit risk have
made, and will likely continue to make, it difficult to obtain funding for our capital needs from the credit and capital markets on terms similar to recent debt and equity offerings.

In
particular, the cost of raising money in the debt and equity capital markets has increased while the availability of funds from those markets has diminished. Also, as a result of
concern about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and
institutional investors have increased interest rates, enacted tighter lending standards and reduced and, in some cases, ceased to provide funding to borrowers.

The
commercial paper markets have recently experienced increased volatility and disruption, resulting in higher costs to issue commercial paper, which has resulted in a reduction in our
use of our commercial paper program. In addition, because of the recent downturn in the financial markets, including the issues surrounding the solvency of many institutional lenders and the recent
failure of several banks, our ability to obtain capital from our Credit Facility may be impaired. For example, as a result of Lehman Brothers Holding, Inc. ("Lehman") filing a petition under
Chapter 11 of the U.S. Bankruptcy Code, Lehman Brothers Bank FSB ("Lehman BB"), a subsidiary of Lehman and a committed lender under our Credit Facility, has declined requests to honor its
commitment to lend up to $82.5 million under our Credit Facility, effectively reducing the amount available to us under our Credit Facility to $1,167.5 million. We may be unable to
utilize the full borrowing capacity under our Credit Facility if other lenders are not willing to provide additional funding to make up the portion of the Credit Facility commitments that
Lehman BB has refused to fund or if any of the remaining 13 committed lenders is unable or unwilling to fund their respective portion of any funding request we make under our Credit Facility.

Due
to these factors, we cannot be certain that funding for our capital needs will be available from the credit and capital markets if needed and to the extent required, on acceptable
terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plan, enhance our existing business, complete acquisitions or
otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Our planned construction and development activities require substantial capital. We may be unable to obtain needed capital or financing on satisfactory terms or at all,
which could delay or curtail our planned construction projects.

We have made and expect to continue making substantial capital expenditures for the construction and development of crude oil and
natural gas infrastructure. One of the primary uses of our capital resources is expenditures for our pipeline construction and expansion projects. We invested approximately

49

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Table of Contents

$1.9 billion
in 2007 and anticipate investing approximately $1.6 billion during 2008 on our construction and development activities.

We
intend to finance our future capital expenditures initially from our cash flow from operations, second from borrowings under our commercial paper program or our Credit Facility and
lastly from borrowings under our $500 million revolving credit agreement with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge Inc. As of September 30, 2008, our
total debt outstanding was $3,736.3 million, we had $151.6 million available in unrestricted cash and short-term investments, $490.1 million of available borrowing
capacity under our Credit Facility and the full $500 million available to us under our revolving credit agreement with Enbridge (U.S.) Inc. We expect to obtain permanent financing
through the issuance of additional debt and equity securities, which we will use to repay amounts initially drawn to fund our construction and development activities. We may be unable to issue
additional debt or equity securities, or to issue these securities on attractive terms due to a number of factors including a lack of demand, poor economic conditions, unfavorable interest rates or
our financial condition or credit rating at the time. In the event additional capital resources are unavailable; we may curtail construction and development activities, or be forced to sell some of
our assets on an untimely or unfavorable basis in order to raise capital.

Item 6.    Exhibits

Reference is made to the "Index of Exhibits" following the signature page, which we hereby incorporate into this Item.

50

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Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.

ENBRIDGE ENERGY PARTNERS, L.P.(Registrant)By:

Enbridge Energy Management, L.L.C.
as delegate of
Enbridge Energy Company, Inc.
as General PartnerDate: October 31, 2008

By:

/s/ STEPHEN J. J. LETWIN Stephen J. J. Letwin Managing Director
(Principal Executive Officer)Date: October 31, 2008

By:

/s/ MARK A. MAKI Mark A. Maki Vice PresidentFinance
(Principal Financial Officer)


51

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Table of Contents

Index of Exhibits

Each exhibit identified below is filed as part of this document. Exhibits not incorporated by reference to a prior filing are
designated by an "*"; all exhibits not so designated are incorporated herein by reference to a previous filing as indicated.

Exhibit
Number

Description3.1

Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement No. 33-43425).3.2

Certificate of Amendment to Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.2 to the Partnership's 2000 Form 10-K/A dated October 9, 2001).3.3

Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated August 15, 2006 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K dated August 16,
2006).3.4

Amendment No. 1 to the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership dated December 28, 2007 (incorporated by reference to Exhibit 3.1 of our Current Report on
Form 8-K dated January 3, 2008).3.5

Amendment No. 2 to the Fourth Amended and Restated Agreement of the Limited Partnership of the Partnership dated August 6, 2008 (incorporated by reference to Exhibit 3.1 of our Current Report on
Form 8-K dated August 6, 2008).4.1

Form of Certificate representing Class A Common Units (incorporated by reference to Exhibit 4.1 to the Partnership's 2000 Form 10-K/A dated October 9, 2001).31.1*

Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2*

Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1*

Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.2*

Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


---